Targeted hydrogenation hydrocracking

ABSTRACT

This invention is directed to a process scheme in which a partial conversion hydrocracking (HCR) unit, preferably preceded by a hydrotreating unit, feeds unconverted oil to a FCC (fluid catalytic cracking ) unit. Most refineries run the FCC unit at the full capacity for optimal asset utilization. During shutdowns of Residue Desulfurization unit(s) which feed an FCC unit, it is desirable to reduce the conversion in the FCC feed hydrocracker. In this way, the feed to FCC unit is maximized. Jet and Diesel products that conform to specifications may be produced during low conversion HCR operation. Furthermore, undesirable over-saturation of the unconverted oil (UCO) from the HCR unit feeding the FCC unit can be avoided. Excess hydrogen consumption can also be avoided. Normally, further aromatic saturation of the middle distillate products from a low conversion HCR is achieved in a separate, post treatment, unit.

FIELD OF THE INVENTION

This invention is directed to a partial conversion hydrocracking (HCR)unit, in which unconverted oil is fed to a Fluid Catalytic Cracking(FCC) unit.

BACKGROUND OF THE INVENTION

In the refining of crude oil, vacuum gas oil hydrotreaters andhydrocrackers are employed to remove impurities such as sulfur, nitrogenand metals from the feed. Typically, the middle distillate boilingmaterial (boiling in the range from 250° F.-735° F.) from VGOhydrotreating or moderate severity hydrocrackers does not meet the smokepoint, the cetane number or the aromatic specification required.

Removal of these impurities in subsequent hydroprocessing stages (oftenknown as upgrading), creates more valuable middle distillate products.Hydroprocessing technology (which encompasses hydrotreating,hydrocracking and hydrodewaxing processes) aims to increase the value ofthe crude oil by fundamentally rearranging molecules. The end productsare also made more environmentally friendly.

In most cases, this middle distillate is separately upgraded by a middledistillate hydrotreater or, alternatively, the middle distillate isblended into the general fuel oil pool or used as home heating oil.Recently hydroprocessing schemes have been developed which permit themiddle distillate to be hydrotreated in the same high pressure loop asthe vacuum gas oil hydrotreating reactor or the moderate severityhydrocracking reactor. The investment cost saving and/or utilitiessaving are significant since a separate middle distillate hydrotreateris not required.

There are U.S. patents which are directed to multistage hydroprocessingwithin a single high pressure hydrogen loop. In U.S. Pat. No. 6,797,154,high conversion of heavy gas oils and the production of high qualitymiddle distillate products are possible in a single high-pressure loopwith reaction stages operating at different pressure and conversionlevels. The flexibility offered is great and allows the refiner to avoiddecrease in product quality while at the same time minimizing capitalcost. Feeds with varying boiling ranges are introduced at differentsections of the process, thereby minimizing the consumption of hydrogenand reducing capital investment.

U.S. Pat. No. 6,787,025 also discloses multi-stage hydroprocessing forthe production of middle distillates. A major benefit of this inventionis the potential for simultaneously upgrading difficult cracked stockssuch as Light Cycle Oil, Light Coker Gas Oil and Visbroken Gas Oil orStraight-Run Atmospheric Gas Oils utilizing the high-pressureenvironment required for mild hydrocracking.

U.S. Pat. No. 7,238,277 provides very high to total conversion of heavyoils to products in a single high-pressure loop, using multiple reactionstages. The second stage or subsequent stages may be a combination ofco-current and counter-current operation. The benefits of this inventioninclude conversion of feed to useful products at reduced operatingpressures using lower catalyst volumes. Lower hydrogen consumption alsoresults. A minimal amount of equipment is employed. Utility consumptionis also minimized.

U.S. Publication 20050103682 relates to a multi-stage process forhydroprocessing gas oils. Preferably, each stage possesses at least onehydrocracking zone. The second stage and any subsequent stages possessan environment having a low heteroatom content. Light products, such asnaphtha, kerosene and diesel, may be recycled from fractionation (alongwith light products from other sources) to the second stage (or asubsequent stage) in order to produce a larger yield of lighterproducts, such as gas and naphtha. Pressure in the zone or zonessubsequent to the initial zone is from 500 to 1000 psig lower than thepressure in the initial zone, in order to provide cost savings andminimize overcracking.

Most refineries run the FCC unit at full capacity for optimal assetutilization. During planned and/or unplanned shutdown of ResidueDesulfurization unit(s) feeding FCC unit, it is desirable to reduce theconversion in the FCC feed hydrocracker in order to maximize the feed toFCC unit. The patents disclosed above do not address the followingissues:

-   -   1. Production of on-specification Jet and Diesel products during        low conversion HCR operation.    -   2. Avoidance of undesirable over-saturation of the unconverted        oil (UCO) from the HCR unit feeding FCC unit and reduce hydrogen        consumption. Normally, further aromatic saturation of the middle        distillate products from a low conversion HCR is achieved in a        separate Post Treatment unit.

SUMMARY OF THE INVENTION

A new process scheme has been developed to design a partial conversionhydrocracking (HCR) unit, feeding the unconverted oil to a FCC unit. Thesteps of this invention are summarized as follows:

-   -   A method for hydroprocessing a hydrocarbon feedstock, said        method employing multiple hydroprocessing zones within a single        reaction loop, each zone having one or more catalyst beds,        comprising the following steps:        -   (a) passing a hydrocarbonaceous feedstock to a first            hydroprocessing zone having one or more beds containing            hydroprocessing catalyst, the hydroprocessing zone being            maintained at hydroprocessing conditions, wherein the            feedstock is contacted with catalyst and hydrogen;        -   (b) passing the effluent of step (a) directly to a hot high            pressure separator, wherein the effluent is separated to            produce a vapor stream comprising hydrogen,            hydrocarbonaceous compounds boiling at a temperature below            the boiling range of the hydrocarbonaceous feedstock,            hydrogen sulfide and ammonia and a liquid stream comprising            hydrocarbonaceous compounds boiling approximately in the            range of said hydrocarbonaceous feedstock;        -   (c) passing the vapor stream of step (b) after cooling and            partial condensation, to a hot high pressure separator where            it is flashed, thereby producing an overhead vapor stream            and a liquid stream, wherein the liquid stream, which            comprises hydrotreated hydrocarbons in the middle distillate            range, is passed to a second hydroprocessing zone;        -   (d) passing the overhead vapor stream from the hot high            pressure separator of step (c), after cooling and contact            with water, said vapor stream comprising hydrogen, ammonia,            hydrogen sulfide, light gases and naphtha, to a cold high            pressure separator, where hydrogen, hydrogen sulfide, and            light hydrocarbonaceous gases are removed overhead, ammonia            is removed from the cold high pressure separator as ammonium            bisulfide in the sour water stripper, and naphtha and middle            distillates are passed to fractionation        -   (e) passing the liquid stream from the hot high pressure            separator of step (b) to a hot low pressure separator, where            it is flashed to produce an overhead stream comprising gases            and a liquid stream comprising unconverted oil;        -   (f) passing the liquid stream of step (e) which comprises            unconverted oil, to a steam stripper, where lighter material            is removed overhead as a vapor stream, and a liquid stream,            which comprises stripped unconverted oil, is recovered.

BRIEF DESCRIPTION OF THE FIGURE

The FIGURE illustrates the flow scheme of the current invention.

DETAILED DESCRIPTION OF THE INVENTION

Feeds

A wide variety of hydrocarbon feeds may be used in the instantinvention. Typical feedstocks include any heavy or synthetic oilfraction or process stream having a boiling point above 392° F. (200°C.). Such feedstocks include vacuum gas oils (VGO), heavy coker gas oil(HCGO), heavy atmospheric gas oil (AGO), light coker gas oil (LCGO),visbreaker gas oil (VBGO), demetallized oils (DMO), vacuum residua,atmospheric residua, deasphalted oil (DAO), Fischer-Tropsch streams,Light Cycle Oil, Light Cycle Gas Oil and other FCC product streams.

Products

The process of this invention is especially useful in the production ofmiddle distillate fractions boiling in the range of about 250-700° F.(121-371° C.). A middle distillate fraction is defined as having anapproximate boiling range from about 250 to 700° F. At least 75 vol. %,preferably 85 vol. % of the components of the middle distillate have anormal boiling point of greater than 250° F. At least about 75 vol. %,preferably 85 vol. % of the components of the middle distillate have anormal boiling point of less than 700° F. The term “middle distillate”includes the diesel, jet fuel and kerosene boiling range fractions. Thekerosene or jet fuel boiling point range refers to the range between 280and 525° F. (138-274° C.). The term “diesel boiling range” refers tohydrocarbons boiling in the range from 250 to 700° F. (121-371° C.).

Gasoline or naphtha may also be produced in the process of thisinvention. Gasoline or naphtha normally boils in the range below 400° F.(204° C.), or C₅ to 400° F. Boiling ranges of various product fractionsrecovered in any particular refinery will vary with such factors as thecharacteristics of the crude oil source, local refinery markets andproduct prices.

Conditions

“Hydroprocessing conditions” is a general term which refers primarily inthis application to hydrocracking or hydrotreating.

Hydrotreating conditions include a reaction temperature between 400°F.-950° F. (204° C.-482° C.), preferably 600° F.-850° F. (315° C.-464°C.); a pressure between 500 to 5000 psig (pounds per square inch gauge)(3.5-34.6 MPa), preferably 1000 to 3000 psig (7.0-20.8 MPa): a feed rate(LHSV) of 0.3 hr-1 to 20 hr-1 (v/v) preferably from 0.5 to 4.0; andoverall hydrogen consumption 300 to 2000 SCF per barrel of liquidhydrocarbon feed (63.4-356 m³/m³ feed).

Typical hydrocracking conditions include a reaction temperature of from400° F.-950° F. (204° C.-510° C.), preferably 650° F.-850° F. (315°C.-454° C.). Reaction pressure ranges from 500 to 5000 psig (3.5-4.5MPa), preferably 1000-3000 psig (7.0-20.8 MPa). LHSV ranges from 0.1 to15 hr-1 (v/v), preferably 0.5 to 5.0 hr-1. Hydrogen consumption rangesfrom 500 to 2500 SCF per barrel of liquid hydrocarbon feed (89.1-445m³H₂/m³ feed).

Catalyst

A hydroprocessing zone may contain only one catalyst, or severalcatalysts in combination.

The hydrocracking catalyst generally comprises a cracking component, ahydrogenation component and a binder. Such catalysts are well known inthe art. The cracking component may include an amorphous silica/aluminaphase and/or a zeolite, such as a Y-type or USY zeolite. Catalystshaving high cracking activity often employ REX, REY and USY zeolites.The binder is generally silica or alumina. The hydrogenation componentwill be a Group VI, Group VlI, or Group VIII metal or oxides or sulfidesthereof, preferably one or more of molybdenum, tungsten, cobalt, ornickel, or the sulfides or oxides thereof. If present in the catalyst,these hydrogenation components generally make up from about 5% to about40% by weight of the catalyst. Alternatively, platinum group metals,especially platinum and/or palladium, may be present as thehydrogenation component, either alone or in combination with the basemetal hydrogenation components molybdenum, tungsten, cobalt, or nickel.If present, the platinum group metals will generally make up from about0.1% to about 2% by weight of the catalyst.

Hydrotreating catalyst is typically a composite of a Group VI metal orcompound thereof, and a Group VIII metal or compound thereof supportedon a porous refractory base such as alumina. Examples of hydrotreatingcatalysts are alumina supported cobalt-molybdenum, nickel sulfide,nickel-tungsten, cobalt-tungsten and nickel-molybdenum. Typically, suchhydrotreating catalysts are presulfided.

In some cases, high activity hydrotreating catalyst suitable for highlevels of hydrogenation, is employed. Such catalysts have high surfaceareas (greater than 140 m.sup.2/gm) and high densities (0.7-0.95 gm/cc).The high surface area increases reaction rates due to generallyincreased dispersion of the active components. Higher density catalystsallow one to load a larger amount of active metals and promoter perreactor volume, a factor which is commercially important. Since depositsof coke are thought to cause the majority of the catalyst deactivation,the catalyst pore volume should be maintained at a modest level(0.4-0.6). A high activity catalyst is at times desired in order toreduce the required operating temperatures. High temperatures lead toincreased coking.

Description of the Preferred Embodiment

Please refer to the FIGURE:

In this process scheme, fresh feed (Stream 9) is passed to the top offixed bed hydrotreater reactor 10. Hydrogen passes through stream 1.Stream 29 is a sidestream from stream 1. From stream 29, streams 3 and 4add hydrogen in between the first and second beds, and second and thirdbeds of reactor 10 respectively. Hydrotreater 10 is loaded with a highactivity hydrotreating catalyst, where most of the feed impurities(heteroatoms) such as nitrogen, sulfur, etc. are removed and some degreeof aromatic saturation is achieved.

The hydrotreated reactor effluent (stream 12) exchanges heat inexchanger 5 with the reactor feed (stream 2 prior to entering theexchanger 5 and stream 9 upon leaving the exchanger 5). Stream 12 isflashed in hot high pressure separator 40 at high temperature andpressure conditions to recover most of the unconverted oil (UCO)components in the liquid phase (stream 13). Vapor leaves separator 40overhead in line 22, and heat is exchanged with hydrogen stream 31 inexchanger 25. Stream 22, which is made up of more than 85 wt % dieseland lighter material, preheats the fractionator feed (not shown in theFIGURE) and generates high pressure steam. Stream 22 is finally cooledto about 200° C. in the hot high pressure separator vapor/recycle gasexchanger 25. Stream 22 is then flashed in hot high pressure separator50. At these relatively high pressure and low temperature conditions,most of the hydrotreated jet and diesel range material is recovered asliquid stream 27 at high pressure, which is pumped(pump 35) to thefeedstream (stream 11), which passes to hydrocracking reactor 20, forfurther processing. The overhead vapor from the hot high pressureseparator 50, stream 23, is then cooled in an air cooler (not shown)before entering a cold high pressure separator (not shown). The overheadvapor stream, stream 23, comprises hydrogen, ammonia, and hydrogensulfide, along with light gases and naphtha. In the cold high pressureseparator (not shown) hydrogen, hydrogen sulfide, and lighthydrocarbonaceous gases are removed overhead, ammonia is removed fromthe cold high pressure separator as ammonium bisulfide in the sour waterstripper. Naphtha and middle distillates are passed to fractionation.

Stream 13 passes to hot low pressure separator 60, where it is flashed.Vapor is removed as stream 28. The hot low pressure separator bottomsare removed as stream 73 and passed to UCO (unconverted oil) stripper30. The material of stream 73 is stream stripped in stripper 30 torecover any lighter material in the UCO stream. Lighter material isremoved as stream 26. Jet and diesel range material is withdrawn as aside draw 17 from the column. Side draw 17 combines with stream 19,stripper bottoms 16 (UCO) to become stream 19. A side stream 18 may betaken from bottoms stream 16. Stream 19, recycle oil, is pumped, viapump 45, to storage drum 70. The recycle oil exits storage drum 70through stream 21 and is pumped, by means of pump 55, to stream 11.Stream 11 is heated in exchanger 15 prior to entering hydrocrackingreactor 20 for further aromatic saturation. The overhead liquid stream26 from the UCO stripper 30 is sent to the main product stripper, andthe offgas is sent to fuel gas (not shown).

The hydrotreated, stripped UCO (stream 16) from the bottom of the UCOstripper, is an excellent quality FCC feed. At this point, a part ofstripped unconverted oil (stream 18) is sent out as FCC feed. Furthersaturation of the FCC feed is thus avoided. Only a limited portion ofthe UCO (mixed with stream19, is passed to hydrocracker 20 for furthersaturation of aromatic components and conversion to distillate products.The amount recycled back is based on the desired overall conversionlevel.

The second stage hydrocracking reactor 20 is loaded with hydrocrackingcatalyst and operates under a clean environment (no heteroatoms),ideally selectively converting the UCO to desired products and furthersaturating the aromatic components to achieve required jet and dieselproperties at different conversion levels. Stream 32 is a sidestreamfrom stream 1. From stream 32, streams 7 and 8 add hydrogen in betweenthe first and second beds and second and third beds of reactor 20respectively.

Both the hydrotreating reactor 10 and hydrocracking reactor 20 aredesigned for the maximum conversion desired. During lower conversionoperation, the hydrotreating reaction is maintained at the sametemperature as the highest conversion case in order to achieve targetdenitrification and desulfurization. The temperature of thehydrocracking reactor is reduced at lower conversions.

The effluent (stream 72) of second stage hydrocracking reactor 20 iscooled (in exchanger 15) to preheat second stage reactor feed (stream11) fractionator feed and cold low pressure separator liquid stream.Stream 72, now renumbered stream 74, combines with hot high pressureseparator vapor stream 23 for further cooling and the removal of highpressure recycle gas. The hydrocarbon liquid from the cold high pressureseparator (not shown) is sent to the fractionation section (not shown)for product recovery.

EXAMPLE

The following table highlights the advantages of the process scheme ofthis invention over a conventional process scheme for a 65,000 BPOD(barrel per operating day) hydrocracking unit: The table indicates thatthere is no need in the current invention for post treatment in order toreach desired product specifications. Furthermore, less hydrogen isconsumed in the scheme of the current invention than in the conventionalcase.

Conventional Process Scheme New Process Scheme Process Scheme SingleStage Once-Through Targeted-Hydrogenation Hydrocracking Fresh Feed Rate,BPSD 65,000 65,000 Overall LHSV, 1 hr 0.7-0.9 0.7-0.9 Product Yield BaseSimilar to Base case Jet & Diesel Quality Needs post treatment foraromatic On specification product at all desired saturation at lowconversion conversions: Jet: S < 10 ppm; Smoke Point > 24 mm Diesel: S <10 ppm; Cetane Index > 50 Chemical H₂ Consumption Base Base - 160 SCFBat 60% conv. Base - 100 SCFB at 40% conv. Base - 50 SCFB at 30% conv.

1. A method for hydroprocessing a hydrocarbon feedstock, said methodemploying multiple hydroprocessing zones within a single reaction loop,each zone having one or more catalyst beds, comprising the followingsteps: (a) passing a hydrocarbonaceous feedstock to a firsthydroprocessing zone having one or more beds containing hydroprocessingcatalyst, the hydroprocessing zone being maintained at hydroprocessingconditions, wherein the feedstock is contacted with catalyst andhydrogen; (b) passing the effluent of step (a) directly to a hot highpressure separator, wherein the effluent is separated to produce a vaporstream comprising hydrogen, hydrocarbonaceous compounds boiling at atemperature below the boiling range of the hydrocarbonaceous feedstock,hydrogen sulfide and ammonia and a liquid stream comprisinghydrocarbonaceous compounds boiling approximately in the range of saidhydrocarbonaceous feedstock; (c) passing the vapor stream of step (b)after cooling and partial condensation, to a second hot high pressureseparator where it is flashed, thereby producing an overhead vaporstream and a liquid stream, wherein the liquid stream, which compriseshydrotreated hydrocarbons in the middle distillate range, is passed to asecond hydroprocessing zone; (d) passing the overhead vapor stream fromthe hot high pressure separator of step (c), after cooling and contactwith water, said vapor stream comprising hydrogen, ammonia, hydrogensulfide, light gases and naphtha, to a cold high pressure separator,where hydrogen, hydrogen sulfide, and light hydrocarbonaceous gases areremoved overhead, ammonia is removed from the cold high pressureseparator as ammonium bisulfide in the sour water stripper, and naphthaand middle distillates are passed to fractionation; (e) passing theliquid stream from the hot high pressure separator of step (b) to a hotlow pressure separator, where it is flashed to produce an overheadstream comprising gases and a liquid stream comprising unconverted oil;(f) passing the liquid stream of step (e) which comprises unconvertedoil, to a steam stripper, where a vapor stream is removed overhead and aliquid stream, which comprises stripped unconverted oil, is recovered.2. The process of claim 1, wherein at least a portion of the strippedunconverted oil of step (f) is passed to a fluid catalytic cracking unitas feed.
 3. The process of claim 1, wherein at least a portion of thestripped unconverted oil of step (f) is combined with the liquideffluent of step (c) to form a liquid stream which is passed to thesecond hydroprocessing zone.
 4. The process of claim 1, wherein thesecond hydroprocessing zone contains at least one bed of hydroprocessingcatalyst suitable for aromatic saturation and ring opening.
 5. Theprocess of claim 4, wherein the liquid stream is contacted underhydroprocessing conditions with the hydroprocessing catalyst, in thepresence of hydrogen to produce middle distillate products.
 6. Theprocess of claim 1, wherein the hydroprocessing conditions of step (a)comprise a reaction temperature of from 400° F.-950° F. (204° C.-510°C., a reaction pressure in the range from 500 to 5000 psig (3.5-34.5MPa), an LHSV in the range from 0.1 to 15 hr-1 (v/v), and hydrogenconsumption in the range from 500 to 2500 scf per barrel of liquidhydrocarbon feed (89.1-445 m³ H₂/m³ feed).
 7. The process of claim 6,wherein the hydroprocessing conditions of step 1(a) preferably comprisea temperature in the range from 650° F.-850° F. (343° C.-454° C.,reaction pressure in the range from 1500-3500 psig (10.4-24.2 MPa), LHSVin the range from 0.25 to 2.5 hr-1, and hydrogen consumption in therange from 500 to 2500 scf per barrel of liquid hydrocarbon feed(89.1-445 m³ H₂/m³ feed).
 8. The process of claim 1, wherein thehydroprocessing conditions of step 1(e) comprise a reaction temperatureof from 400° F.-950° F. (204° C.-510° C., a reaction pressure in therange from 500 to 5000 psig (3.5-34.5 MPa), an LHSV in the range from0.1 to 15 hr-1 (v/v), and hydrogen consumption in the range from 500 to2500 scf per barrel of liquid hydrocarbon feed (89.1-445 m³ H₂/m³ feed).9. The process of claim 9, wherein the hydroprocessing conditions ofstep 1(e) preferably comprise a temperature in the range from 650 m³H₂/m³ feed F.-850 m³ H₂/m³ feed F. (343° C.-454° C., reaction pressurein the range from 1500-3500 psig (10.4-24.2 MPa), LHSV in the range from0.25 to 2.5 hr-1, and hydrogen consumption in the range from 500 to 2500scf per barrel of liquid hydrocarbon feed (89.1-445 m³ H₂/m³ feed). 10.The process of claim 1, wherein the feed to step 1(a) compriseshydrocarbons boiling in the range from 500° F. to 1500° F.
 11. Theprocess of claim 1, wherein the feed is selected from the groupconsisting of vacuum gas oil, heavy atmospheric gas oil, delayed cokergas oil, visbreaker gas oil, FCC light cycle oil, and deasphalted oil.12. The process of claim 1, wherein the hydroprocessing catalystcomprises both a cracking component and a hydrogenation component. 13.The process of claim 12, wherein the hydrogenation component is selectedfrom the group consisting of Ni, Mo, W, Pt and Pd or combinationsthereof.
 14. The process of claim 3, wherein the cracking component maybe amorphous or zeolitic.
 15. The process of claim 11, wherein thezeolitic component is selected from the group consisting of Y, USY, REX,and REY zeolites.
 16. The process of claim 1, wherein the middledistillate products produced do not require additional treatment to meetproduct specifications.
 17. The process of claim 16, wherein the sulfurcontent of jet fuel is less than 10 ppm, the smoke point is greater than24 mm, the sulfur content of diesel is less than 10 ppm, and the cetaneindex is greater than
 50. 18. The process of claim 1, in which smalleramounts of hydrogen are used than in single stage once-throughhydrocracking.
 19. The process of claim 18, wherein the amount ofhydrogen used is 160 SCF per barrel lower than the amount used in singlestage once-through hydrocracking at 60% conversion, 100 SCF per barrellower than the amount used in single stage once-through hydrocracking at40% conversion, and 50 SCF per barrel lower than the amount used insingle stage once-through hydrocracking at 30% conversion.
 20. Theprocess of claim 1, wherein the hydrotreating occurs in the firstreaction zone and hydrocracking occurs in the second reaction zone.